In drilling operations for oil and gas, the retrieval of cylindrical samples of rock materials, known as cores, from underground locations is a common practice. The cores are studied to gain a better understanding of the fabric of the reservoir materials and their inherent properties to store and flow oil, gas and water.
One common method of gaining information on the reservoir material properties is to take continuous measurements of the wellbore properties for each well using electrical, sonic, radioactive and other devices, a process known as logging. If the information in the log for a particular depth in the wellbore can be combined with the information derived from a core sample taken at that depth, a fuller understanding of the reservoir is possible. However, in order to extract meaningful data from the logs for this purpose, it is essential to be able to match the depth as recorded in the log with the core sample taken at that depth.
Unfortunately, this is not a straightforward process. In general, the depth at which a particular core is taken as recorded by the drilling crew is subject to large errors as the depths are calculated by adding the lengths of individual drill pipes, which are subject to various expansion-compression loads in the borehole. Additionally, the incomplete recovery of cores (i.e. some pieces are missing due to mechanical failure and drilling fluid circulation related wash-outs), coupled with the current practice of lumping all the unrecovered lengths at the bottom of each core barrel, which is a tube holding cores during drilling, also contributes to the uncertainty in core depth reporting. The errors or uncertainties can lead to improper matches between log and core data, resulting in costly mistakes in reservoir performance predictions.
One conventional method for attacking this problem has been gamma-scanning in petrophysical laboratories for comparing the core depths with log depths. While gamma-scanning is easy to apply in sandstone reservoirs, the absence of the usual markers present in the typical sand/shale sequences and poor signals make it difficult to obtain satisfactory depth matches in the carbonate cores.
In another aspect of oil/gas field drilling, X-ray computed tomography of cores has been used to measure, for example porosity, relative permeability, fluid saturations, bulk density and mineralogy. The process makes it possible to look inside core materials in a non-destructive manner for visualizing heterogeneities, lithology variations and has been used to compute such core parameters for almost 20 years. Examples of patents disclosing the use of this process are U.S. Pat. Nos. 5,036,193, 4,868,751, 5,359,194, 5,984,023, 6,003,620 and 6,220,371 B1.
U.S. Pat. No. 4,542,648 to Vinegar et al. is directed to the use of an X-ray computerized axial tomography (CAT) scanning technique in a method of correlating a core sample with its original position in a borehole. This method recognizes that there is a relationship between certain quantitative data (mass attenuation coefficients) generated by a typical CT scanner and bulk densities at generally high X-ray energies. In one embodiment, the method involves convolving interpolated density values derived from CT measured average attenuation coefficients with the response function of the logging tool to generate convolved density values that are cross correlated with the log density values to obtain the maximum cross correlation function for the correlation depth. In another embodiment, the method involves convolving effective atomic numbers with the response function of the tool to obtain convolved effective atomic numbers that are cross correlated with the photoelectric log values.
However, this method requires the use of complicated mathematics, which makes its procedure difficult for use by typical workers for predicting depth shifts. Moreover, with this method it is difficult to correlate the CT data with the density logs as it depends on what was present outside the core material.